Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Item 2.02 Results of Operations and Financial Condition.

On August 6, 2018, Centennial Resource Development, Inc. (the “Company”) issued a press release announcing its financial and operational results for the second quarter of 2018 and updated 2018 operational tragets. A copy of the press release is furnished as Exhibit 99.1 hereto.

The information furnished pursuant to this Item 2.02 and Item 7.01 shall not be deemed to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and will not be incorporated by reference into any filing under the Securities Act of 1933, as amended, unless specifically identified therein as being incorporated therein by reference.

Item 7.01. Regulation FD Disclosure.

The information set forth under Item 2.02 is incorporated herein by reference.

Second quarter net income increased 206 percent to $63.5 million, or $0.24 per
diluted share, compared to $20.8 million, or $0.09 per diluted share, in the prior year period.

Average daily crude oil production increased 79 percent in the second quarter and 125 percent for the first half of 2018 compared to prior year periods.

“As evidenced by our results, we continue to deliver some of the best wells in Reeves County and remain on track to achieve our full-year production targets with lower unit costs. These strong operational reports were somewhat offset by the impact of the timing of completions in addition to higher than anticipated volumes shut-in by offset frac jobs. With approximately half of our second quarter completions coming online in June, the production impact from these wells was only minimal during the quarter,” said Mark G. Papa, Chairman and Chief Executive Officer.

NGL volumes increased 50% to 12,389 Bbls/d compared to the first quarter 2018 and accounted for 22% of total equivalent volumes compared to 15% in the prior quarter. The increase was attributable to the Company’s primary gas processor shifting to ethane recovery during the quarter and extracting additional liquids from the gas stream to provide enhanced economics for a portion of our production.

“The change to ethane recovery was solely an economic decision, and we recognized higher revenue as a result,” Papa said. “The increase in NGL volumes increased our overall equivalent production causing oil as a percentage of total production to decline quarter-over-quarter, but had no effect on actual oil volumes.”

Operational Update

Centennial’s operational shift to multi-well pad development in the Delaware Basin has yielded positive results while driving efficiencies and increasing economic returns. In Reeves County, Centennial posted robust results from the Third Bone Spring Sand, Upper Wolfcamp A, Lower Wolfcamp A and Wolfcamp C intervals.

“In our second full year of operations, we have made the shift from drilling one-off wells to a full development program. During the second quarter, ninety percent of wells completed were on multi-well pads, reflecting the transition to more efficient, higher return operations. The long-term economic benefits from this development mode will offset any short-term irregular production trends,” Papa said.

The Red Rock A Unit T09H and U04H (74% WI) were drilled using a stacked, staggered pattern in the Third Bone Spring Sand and Upper Wolfcamp A intervals, respectively, with effective 10,900 foot laterals. The Red Rock A Unit T09H achieved an initial 30-day production rate of 1,578 Boe/d, with 1,143 Bbls/d of oil. The Red Rock A Unit U04H reported an initial 30-day production rate of 1,268 Boe/d, with 940 Bbls/d of oil.

“The Red Rock A Unit wells prove the viability of simultaneously pairing the Third Bone Spring Sand and Upper Wolfcamp A intervals. The Unit T09H was a key well, it was our second successful Third Bone Spring Sand test and our first co-development test of another interval,” Papa said. “We have organically added a new, high rate of return play on a portion of our Reeves County acreage with the success of our drilling program. We plan to test the Third Bone Spring Sand in other areas throughout the year and expect this interval to play a larger role in Centennial’s 2019 development program.”

The CWI Long A U31H, B U40H and C U49H (64% WI) were drilled in the Upper Wolfcamp A interval with approximate 9,850-foot laterals. These wells achieved initial 30-day production rates of 2,158 Boe/d (78% oil), 2,899 Boe/d (78% oil) and 2,278 Boe/d (78% oil), respectively. The three-well pad delivered an average initial 30-day oil production rate of 194 Bbls/d per 1,000 foot of lateral per well.

“The CWI Long pad represents our best and most productive wells drilled to date. Combined, these wells have produced over 200,000 barrels of oil during their first forty days on production,” Papa said.

On the Company’s Miramar acreage, the Ninja 4-50 49 2H, 3H, 4H and 5H (89% WI) were drilled on a four-well pad targeting the Lower Wolfcamp A, Upper Wolfcamp A, Wolfcamp C and Upper Wolfcamp A intervals, respectively. Drilled with an average extended lateral length of 9,800 feet, the wells delivered an average initial 30-day production rate of 1,878 Boe/d (58% oil) per well. During its initial 60-day production period, the pad produced over 225,000 barrels of oil.

Targeting the Upper Wolfcamp A zone, the Balmorhea State G 8H, H 9H and I 10H (100% WI) wells were drilled with average 6,150 foot effective laterals. Each well began production at an average initial 30-day production rate of 1,337 Boe/d (77% oil) per well, or 166 Bbls/d of oil per 1,000 foot of lateral.

“Notably, all of our highlighted wells this quarter commenced production in mid-May or June and, therefore, had only a minor impact on second quarter production," Papa said. “Given these robust results, we feel confident headed into the second half of the year.”

Total capital expenditures incurred for the quarter were $203.2 million compared to $169.6 million in the prior year period. During the second quarter, drilling and completion capital expenditures incurred were approximately $162.7 million. Centennial’s facilities, infrastructure, land and other capital totaled approximately $40.5 million during the quarter.

Midstream and Marketing Update

Centennial recently entered into a firm sales agreement for a significant portion of its oil production with a large diversified crude oil purchaser. Utilizing the buyer’s existing firm transport capacity out of the Basin, the six-year agreement provides for firm gross sales of 20,000 Bbls/d beginning in January 2019, increasing to 30,000 Bbls/d in 2020 for the remainder of the agreement.

“This agreement secures flow assurance for a large portion of our crude oil volumes. Additionally, it provides access to Brent-weighted pricing in 2020, enabling us to diversify our pricing portfolio longer term,” Papa said. “We are working with other major marketers and expect to execute similar contracts within the next few months. Our goal is to secure transportation for essentially all of our future crude oil production.”

Centennial also finalized transportation agreements for all of its expected associated natural gas production. Through firm transportation and sales agreements, Centennial has ensured flow assurance both to the Waha Hub and out of the Permian Basin through the end of 2021.

“We expect natural gas egress will become a significant issue in the Permian Basin by early 2019. These transportation agreements not only provide flow assurance for our natural gas, but also enable Centennial to recognize the economic value of our natural gas and NGL streams,” Papa said.

Updated 2018 Operational Targets

Based on recent operational results, Centennial lowered its full-year 2018 guidance ranges for LOE, Cash G&A, GP&T and DD&A on a per unit basis. As a result of ethane recovery and anticipated further extraction of additional NGLs from the natural gas stream, the Company adjusted its full-year 2018 total equivalent production target as illustrated in the Appendix to this press release.

“Centennial delivered second quarter unit costs either below or at the low-end of our full-year guidance ranges. We have the confidence to lower our total unit cost for the second consecutive year,” Papa said. “Overall, our operations team continues to do an outstanding job driving down costs and keeping drilling and completion costs in-line, even in light of the current inflationary oilfield service cost environment in the Permian Basin.”

(For a summary table of Centennial’s updated 2018 operational guidance, please see the Appendix to this press release.)

Capital Structure and Liquidity

As of June 30, 2018, Centennial had $43 million in cash on hand and $430 million of long-term debt, inclusive of $30 million outstanding under its revolving credit facility and $400 million of senior unsecured notes. Total liquidity was approximately $612 million, including the impact of letters of credit.

Hedge Position

As of August 6, 2018, Centennial had no fixed-price crude oil hedges. For the period July to December 2018, Centennial’s crude oil basis hedges represent approximately 23% of its expected crude oil production (using the mid-point of guidance) at a weighted average price of $(2.38) per barrel. For 2019, Centennial has 8,030 Bbls/d of crude oil basis hedges in place at a weighted average price of $(6.88) per barrel. During the quarter, Centennial entered into additional natural gas swap and basis hedges effective 2019. (For a summary table of Centennial’s derivative contracts as of August 1, 2018, please see the Appendix to this press release.)

Quarterly Report on Form 10-Q

Centennial’s financial statements and related footnotes will be available in its Quarterly Report on Form 10-Q for the three months ended June 30, 2018, which is expected be filed with the U.S. Securities and Exchange Commission (“SEC”) on August 6, 2018.

Conference Call and Webcast

Centennial will host an investor conference call on Tuesday, August 7, 2018 at 8:00 a.m. Mountain (10:00 a.m. Eastern) to discuss second quarter 2018 operating and financial results. Interested parties may join the webcast by visiting Centennial’s website at www.cdevinc.com and clicking on the webcast link or by dialing (800) 789-3525, or (442) 268-1041 for international calls, (Conference ID: 7818579) at least 15 minutes prior to the start of the call. A replay of the call will be available on Centennial’s website or by phone at (855) 859-2056 (Conference ID: 7818579) for a 14-day period following the call.

About Centennial Resource Development, Inc.

Centennial Resource Development, Inc. is an independent oil and natural gas company focused on the development of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin. The Company’s assets and operations, which are held and conducted through Centennial Resource Production, LLC, are concentrated in the Delaware Basin, a sub-basin of the Permian Basin. For additional information about the Company, please visit www.cdevinc.com.

Cautionary Note Regarding Forward-Looking Statements

The information in this press release includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact included in this press release, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this press release, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.

Forward-looking statements may include statements about:

•

our business strategy and future drilling plans;

•

our reserves and our ability to replace the reserves we produce through drilling and property acquisitions;

the timing and amount of our future production of oil, natural gas and NGLs;

•

our hedging strategy and results;

•

our competition and government regulations;

•

our ability to obtain permits and governmental approvals;

•

our pending legal or environmental matters;

•

the marketing and transportation of our oil, natural gas and NGLs;

•

our leasehold or business acquisitions;

•

general economic conditions;

•

credit markets;

•

uncertainty regarding our future operating results;

•

our plans, objectives, expectations and intentions contained in this press release that are not historical; and

•

the other factors described in our Annual Report on Form 10-K for the year ended December 31, 2017, and any updates to those factors set forth in our subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the development, production, gathering and sale of oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks described in our filings with the SEC.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.

Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this press release are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this press release.

Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net income before interest expense, income taxes, depreciation, depletion and amortization, exploration costs, impairment and abandonment expenses, non-cash gains or losses on derivatives, non-cash stock-based compensation, gains and losses from the sale of assets and transaction costs. Adjusted EBITDAX is not a measure of net income as determined by generally accepted accounting principles (“GAAP”).

Our management believes Adjusted EBITDAX is useful as it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies.

The following table presents a reconciliation of Adjusted EBITDAX to net income, our most directly comparable financial measure calculated and presented in accordance with GAAP:

For the Three Months Ended June 30, 2018

For the Six Months Ended June 30, 2018

(in thousands)

2018

2017

2018

2017

Adjusted EBITDAX reconciliation to net income:

Net income attributable to Class A Common Stock

$

63,541

$

20,762

$

129,631

$

30,585

Net income attributable to noncontrolling interest

3,941

2,436

8,623

3,320

Interest expense

5,791

707

11,604

1,117

Income tax expense

19,940

9,069

39,077

9,069

Depreciation, depletion and amortization

74,946

34,300

140,956

60,460

Impairment and abandonment expenses

1,784

—

1,784

(29

)

Non-cash portion of derivative gain

(11,534

)

(2,256

)

(19,016

)

(6,412

)

Stock-based compensation expense

4,166

2,558

8,118

4,928

Exploration expense

1,867

1,289

5,314

2,470

Transaction costs

—

457

—

1,344

(Gain) loss on sale of oil and natural gas properties

141

(7,191

)

126

(7,357

)

Adjusted EBITDAX

$

164,583

$

62,131

$

326,217

$

99,495

Centennial Resource Development, Inc.

Operating Highlights

For the Three Months Ended June 30,

For the Six Months Ended June 30,

2018

2017

2018

2017

Operating revenues (in thousands):

Oil sales

$

174,156

$

70,735

$

348,997

$

117,416

Natural gas sales

13,721

12,133

32,301

20,374

NGL sales

29,886

8,196

52,363

14,371

Oil and gas sales

$

217,763

$

91,064

$

433,661

$

152,161

Average sales prices:

Oil (per Bbl)

$

61.21

$

44.57

$

61.37

$

46.39

Effect of derivative settlements on average price (per Bbl)

1.69

0.24

0.89

0.05

Oil net of hedging (per Bbl)

$

62.90

$

44.81

$

62.26

$

46.44

Average NYMEX price for oil (per Bbl)

$

68.07

$

48.32

$

65.55

$

50.05

Oil differential to NYMEX

(6.86

)

(3.75

)

(4.18

)

(3.66

)

Natural gas (per Mcf)

$

1.81

$

2.78

$

2.12

$

2.83

Effect of derivative settlements on average price (per Mcf)

0.05

(0.02

)

0.03

(0.04

)

Natural gas net of hedging (per Mcf)

$

1.86

$

2.76

$

2.15

$

2.79

Average NYMEX price for natural gas (per Mcf)

$

2.85

$

3.14

$

2.96

$

3.10

Natural gas differential to NYMEX

(1.04

)

$

(0.36

)

$

(0.84

)

(0.27

)

NGL (per Bbl)

$

26.52

$

21.34

$

27.99

$

22.81

Net production:

Oil (MBbls)

2,845

1,587

5,687

2,531

Natural gas (MMcf)

7,572

4,372

15,255

7,205

NGL (MBbls)

1,127

384

1,871

630

Total (MBoe)

5,235

2,700

10,101

4,362

Average daily net production volume:

Oil (Bbls/d)

31,271

17,435

31,421

13,982

Natural gas (Mcf/d)

83,205

48,042

84,283

39,807

NGL (Bbls/d)

12,389

4,222

10,340

3,481

Total (Boe/d)

57,528

29,664

55,808

24,097

Centennial Resource Development, Inc.

Operating Expenses

For the Three Months Ended June 30,

For the Six Months Ended June 30,

2018

2017

2018

2017

Operating costs (in thousands):

Lease operating expenses

$

19,182

$

8,273

$

35,458

$

15,551

Severance and ad valorem taxes

14,208

4,723

28,381

7,910

Gathering, processing and transportation expenses

15,296

7,403

29,124

12,647

Operating costs per Boe:

Lease operating expenses

$

3.66

$

3.06

$

3.51

$

3.57

Severance and ad valorem taxes

2.71

1.75

2.81

1.81

Gathering, processing and transportation expenses

2.92

2.74

2.88

2.90

Centennial Resource Development, Inc.

Condensed Consolidated Statements of Operations

(in thousands, except per share data)

For the Three Months Ended June 30,

For the Six Months Ended June 30,

2018

2017

2018

2017

Operating revenues

Oil and gas sales

$

217,763

$

91,064

$

433,661

$

152,161

Operating expenses

Lease operating expenses

19,182

8,273

35,458

15,551

Severance and ad valorem taxes

14,208

4,723

28,381

7,910

Gathering, processing and transportation expenses

15,296

7,403

29,124

12,647

Depreciation, depletion and amortization

74,946

34,300

140,956

60,460

Impairment and abandonment expenses

1,784

—

1,784

(29

)

Exploration expense

1,867

1,289

5,314

2,470

General and administrative expenses

13,809

11,822

28,106

22,706

Total operating expenses

141,092

67,810

269,123

121,715

Income from operations

76,671

23,254

164,538

30,446

Other income (expense)

Gain (loss) on sale of oil and natural gas properties

(141

)

7,191

(126

)

7,357

Interest expense

(5,791

)

(707

)

(11,604

)

(1,117

)

Net gain (loss) on derivative instruments

16,697

2,529

24,540

6,288

Other income (expense)

(14

)

—

(17

)

—

Other income (expense)

10,751

9,013

12,793

12,528

Income before income taxes

87,422

32,267

177,331

42,974

Income tax expense

(19,940

)

(9,069

)

(39,077

)

(9,069

)

Net income

67,482

23,198

138,254

33,905

Less: Net income attributable to noncontrolling interest

3,941

2,436

8,623

3,320

Net income attributable to Class A Common Stock

$

63,541

$

20,762

$

129,631

$

30,585

Income per share of Class A Common Stock:

Basic

$

0.24

$

0.09

$

0.49

$

0.14

Diluted

$

0.24

$

0.09

$

0.49

$

0.14

The following table summarizes the approximate volumes and average contract prices of swap contracts the Company had in place as of June 30, 2018 and additional contracts entered into through August 1, 2018:

Period

Volume (Bbl)

Volume (Bbls/d)

Weighted Average Differential ($/Bbl)(1)

Crude oil basis swaps

July 2018 - September 2018

828,000

9,000

$

(2.38

)

October 2018 - December 2018

828,000

9,000

(2.38

)

January 2019 - March 2019

540,000

6,000

(5.34

)

April 2019 - June 2019

91,000

1,000

(10.00

)

July 2019 - September 2019

1,380,000

15,000

(9.03

)

October 2019 - December 2019

920,000

10,000

(4.24

)

(1)

The oil basis swap transactions are settled based on the difference between the arithmetic average of the ARGUS MIDLAND WTI and ARGUS WTI CUSHING settlements, during the relevant calculation period.

Period

Volume (MMBtu)

Volume (MMBtu/d)

Weighted Average Fixed Price ($/MMBtu)(1)

Natural Gas Swaps - Henry Hub

January 2019 - December 2019

10,950,000

30,000

$

2.78

Natural Gas Swaps - West Texas WAHA

January 2019 - December 2019

5,475,000

15,000

1.61

Period

Volume (MMBtu)

Volume (MMBtu/d)

Weighted Average Differential ($/MMBtu)(2)

Natural gas basis swaps

July 2018 - December 2018

920,000

5,000

$

(0.43

)

January 2019 - December 2019

12,775,000

35,000

(1.31

)

(1)

The natural gas swap contracts are settled based on the month’s average daily NYMEX price of Henry Hub Natural Gas or Inside FERC’s West Texas WAHA price of natural gas.

(2)

The natural gas basis swap contracts are settled based on the difference between Inside FERC’s West Texas WAHA price of natural gas and the NYMEX price of Natural Gas during the relevant calculation period.